2014 Utility Regulators' Forum

The mix of state utility regulation is as diverse as the mix of fuels that feed electric generation. And that's why Public Utilities Fortnightly has chosen to speak with an assortment of utility regulators who can shed light on the most pressing matters in their respective states.

In the nation's southern swath, there's Georgia, which relies heavily on coal, but that must now adapt to a changing regulatory culture - one that downplays coal and builds up other fuels, namely natural gas and some renewables. And so Georgia has taken up the challenge: It has taken the lead on nuclear and is working to install utility-scale solar.

Moving up the East Coast, there are Maryland and New York, each of which has chosen to tackle its carbon emissions, and each of which has taken action to curb pollutants that have drifted its way, from the South and the Midwest. The two states, for example, count themselves part of the Regional Greenhouse Gas Initiative (RGGI), whereby they participate in a cap-and-trade program to reduce their heat-trapping emissions. Monies collected selling credits go toward expanding their green energy options, and toward researching new technologies.

New York, meantime, is expanding its portfolio of options when it comes to dealing with disasters, whether manmade or natural: a deadly natural gas pipeline explosion and Super Storm Sandy. And to top it off, the state has imposed a shale gas fracking moratorium, even while it works to expand its use of natural gas.

Finally, we head West, to California, the state that has pushed its incumbent utilities to build out their green energy options to 33 percent by 2020. To that end, it has adopted an energy storage mandate that it hopes will accelerate the trend, and the technology, so that other states would take this route. And the public utilities commission there is doing all this even while coping with a troubled and retiring nuclear facility and a natural gas pipeline blast.

"We have been handed a new set of rules. … It’s the federal government forcing the state’s hand." Chuck Eaton, Chairman, Georgia PSC

To learn more about these issues, and others, we have chatted with:

• Chuck Eaton, chairman, Georgia Public Service Commission.

• Michael R. Peevey, president, California Public Utilities Commission.

• Kelly Speakes-Backman, commissioner, Maryland Public Service Commission, and chair of the Board of Directors, RGGI, Inc.

"EPA’s Clean Power Plan has definitely increased interest in regional programs like RGGI." - Kelly Speakes-Backman, Maryland PSC

• Audrey Zibelman, chair, New York State Public Service Commission

Their responses reveal not only the diversity of policies among the states, but show how difficult will be their task to comply with federal initiatives to remake the energy industry.

 

Chuck Eaton, Chairman, Ga. PSC

FORTNIGHTLY: What is your position on President Obama's Clean Power Plan?

"We will achieve the 33 percent goal at a relatively modest cost to ratepayers." - Michael R. Peevey, President, California PUC

Chuck Eaton, Chairman, Ga. PSC: I expect that [section] 111(d) of the Clean Air Act will have legal challenges and will work its way through the court system. If the rule stands the way it is, we will have to comply. However, Georgia's commissioners are unanimously opposed to the rule. The most egregious aspect is that we are not getting credit for Plant Vogtle, which is the nuclear power plant that we are building.

Furthermore, the building blocks are unrealistic and the administration is not putting targets in there. That said, we have already taken steps to reduce our reliance on coal and we are building nuclear, although we are not getting credit for that, which is something that we hope will change during our recurring dialogues.

That's because the Obama administration is nuclear friendly. We have taken steps in anticipation of some sort of carbon reduction rule, mainly Plant Vogtle, which is 2,000 megawatts. That plant was formally approved before this rule came out. But it won't be finished for a few years. Of all the targets and all the aspects of the rule and how it would apply to Georgia, we are most focused getting the nuclear plant included.

FORTNIGHTLY: How do you feel about all the coal retirements taking place in Georgia?

"The distributed grid is far more advanced than just a few years ago. There are hundreds of companies willing to risk capital to get involved. " - Audrey Zibelman, Chair, New York PSC

Eaton: We have an integrated resource plan that looks out 20 years and which we review every three years. It looks at the kinds of power plants we will need to meet our electricity demand. When it comes to shedding the coal plants, we approved that. We voted to shut down 16 units. That is at least a fourth of the fleet.

Now, I disagree with having to shut down those plants. We have been handed a new set of rules. In our minds, that was the best way to go forward. Instead of spending hundreds of millions improving those plants and instead of dealing with moving goal posts, shutting down coal plants was the best alternative. As commissioners, we could have opted to invest in those coal plants by making environmental upgrades. But then regulators could change the rules of the game on you. Section 111(d) is an example: It may have rendered those upgrades obsolete.

FORTNIGHTLY: Isn't natural gas a viable option right now?

Eaton: There has been a trend to replace coal with natural gas, which is a short term option. I'm not sure that this is a good long term strategy: Less diversity equals higher risks. Right now, most people are pretty bullish on natural gas. But nothing will suck up supply more than a bunch of electric utilities dedicating their resources to it. Diversity needs to rule the day.

It is difficult to predict what will happen 3 or 4 years down the road. Plant Vogtle is a 60- year investment. But natural gas is the polar opposite of nuclear energy. It is cheap to build up front but it will likely have wild fuel price swings. Nuclear is expensive to build up front but it cheap to operate. They are a good offset to each other.

Natural gas, however, is the "enemy" right now to all the other fuels and technologies: solar, coal and nuclear and energy efficiency. The extremely low price of natural gas makes it difficult to justify those other things. But we still need to look at diversity. You can't rely solely on natural gas forever. The minute you do that, prices will skyrocket and we will all be in big trouble.

When everyone talks about dirt cheap natural gas prices that is the time to get out. As more and more utilities try to suck up the natural gas as an option, that will drive up prices. Supply and demand will work its way out and you will see upward pressure on rates. No one has a crystal ball. But that is where diversity comes in. If you take away coal, that means less diversity and less diversity means higher risks. Think Hurricane Katrina.

I have happily approved many natural gas projects and think it is a great part of the mix. I'm just concerned that the country is becoming overly reliant on it.

FORTNIGHTLY: What is your view of carbon capture and specifically of the project that Southern Company has in Mississippi that would use the carbon to enhance oil recovery?

Eaton: I'm not sure that Georgia is a good fit for the carbon capture project going on Mississippi. We are geologically different. We don't have those same resources. I don't see that as option here in Georgia. Without having a discussion about it, I cannot conjecture about its possibilities nationally.

FORTNIGHTLY: What about advanced coal technologies, generally, and how they have been applied and cut emissions?

Eaton: We have reduced the traditional pollutants by amazing levels. Just look at SOx (sulfur dioxide,) NOx (nitrogen oxide) and mercury. But don't get that confused with the new EPA rules for carbon. That is a climate change issue. Coal plants are the target here.

If utilities are forced to shut down these units and shift to higher cost options, then it will be reflected in the rates that manufacturers pay. If it was simply that natural gas was the cheapest option, then everyone would shift to that. But shutting down a plant with 20 years of life still in it means you have stranded costs. If we decide to build a plant that has a 60-year amortization schedule and then decide to shut it down 20 years early, the ratepayers still have to pay down the balance on that plant.

But you are also making additional capital investment in a different plant. And so you are paying for something twice but only getting one benefit. You can only imagine what that does to the rates. In the end, it is the federal government forcing the state's hand. Rates will go up and it then becomes more difficult for a manufacturing facility to operate. If China and India do not have the same constraints, then jobs will shift there.

FORTNIGHTLY: Does solar energy figure into Georgia's integrated resource plan?

Eaton: We were very conservative, initially, when it came to solar. But it is now benefiting our state. The price that we pay for solar panels is a third of what it was six years ago. You can make the argument that someone else who got in early had paid three-times what we had paid in Georgia. There is a benefit to being conservative. Over the last few years, we have been very innovative. By 2016, Georgia is slated to have 900 megawatts of solar and it is not putting upward pressure on rates.

It is both utility-scale solar that is sent over the transmission wires and distributed solar that is localized and that is generated by rooftop solar panels. Utility-scale, though, is a bigger portion.

Solar is giving us an option to diversify. But it is not putting upward pressure on rates. The commission has recently pushed for more solar. If you looked at solar six years ago, you would have determined that it was not competitive here in Georgia. Now it is and you need to have another look at it. But you can't rely on it because of its intermittent nature. Still, it provides diversity in peak usage scenarios.

FORTNIGHTLY: Isn't biomass an option in Georgia and can't it be used in conjunction with existing coal plants?

Eaton: We have approved 250 megawatts of biomass that is projected to come on line in 2017. There is no one thing you can point to that will take or supplement coal's market share. If you take coal out of the mix, it will provide more opportunity for not just natural gas but also nuclear, solar and biomass.

 

Kelly Speakes-Backman, Commissioner, Md. PSC

FORTNIGHTLY: Maryland is connected to the Northeast and, as such, is part of RGGI. Along those lines, how is the cap-and-trade system working out for you? Reducing emissions? What about energy costs? Bringing innovative technologies on line? Please elaborate.

Kelly Speakes-Backman, commissioner, Md. PSC: RGGI has exceeded our expectations. We are now in our sixth year and our nine states in the Northeast and Mid-Atlantic have built an efficient, effective, transparent and economically beneficial system. Our states have experienced a 40 percent reduction in power sector carbon pollution since 2005, while our regional economy has grown 7 percent (adjusted for inflation) - much more than surpassing our initial goal of reducing carbon pollution by 10 percent. Proceeds from RGGI allowance auctions help to fund complementary state strategic energy programs and initiatives to support clean, affordable and reliable power. This pairs our states' carbon reduction goals with economic development for the region.

FORTNIGHTLY: What do you say to those who argue that such a system is essentially a tax on electricity and unfair to consumers?

Speakes-Backman: Carbon pollution has a cost and a value. Rather than a "tax," which is often simply absorbed into general budgets, the RGGI states decided to auction a majority of the RGGI allowances to reinvest directly as a benefit to support the transformation of energy use and production.

Rather than give allowances away for free, RGGI states capture the economic value for the direct benefit of its citizens, The RGGI states invest a majority of the auction proceeds in strategic energy and consumer benefit programs, including energy efficiency, renewable and clean energy, and direct bill assistance programs. Through 2013, the RGGI states have invested more than $950 million in RGGI proceeds in these strategic energy initiatives.

An independent report by the Analysis Group found that through the end of the decade, auction proceeds from RGGI's first three years will generate $1.6 billion in net economic benefit. These economic benefits are being fueled by $1.3 billion in energy bill savings for customers - and these economic benefits are occurring in each and every state.

RGGI works within the existing construct of electricity markets, to provide a direct signal to the power sector that supports fuel switching, on-site efficiency improvements, the retirement of high-emitting plants, the construction of new more efficient plants, and other measures that reduce emissions.

By allowing the market to develop the appropriate price signal, rather than assigning an arbitrary, administratively-determined tax amount, the RGGI construct ensures that the most cost-effective reductions are implemented across our region.

FORTNIGHTLY: What do you to say to those who maintain that the carbon issue is global and that any localized efforts are basically fruitless?

Speakes-Backman: Carbon pollution is a global issue. It is also a local, regional, and national issue. By that I mean it is a global problem with local impacts. A variety of initiatives at all levels are needed to tackle this problem.

In Maryland, Governor O'Malley and the General Assembly have recognized our regional role by passing legislation establishing goals to reduce greenhouse gas (GHG) emissions by 25% by 2020.

One advantage of state and regional initiatives is that they can achieve significant pollution reduction, and be optimized for adaptation to local circumstances, such as geography, energy infrastructure, weather, and economy. It is this customization and adaptability that allows for the most cost effective solutions to reduce pollution and support economic growth.

Even so, depending on the solution suggested, there are times when a broader approach is more cost-effective. An example is taking a regional approach to carbon pollution reduction from power plants. The existing structure of the regional energy markets can be utilized to find the least cost pollution reduction schemes across a broader geographical region, minimizing the costs of such actions.

FORTNIGHTLY: What's the major difference between your plan and that of California?

Speakes-Backman: The RGGI states work closely with others states and regions, including California, to share lessons learned and best practices in the design and implementation of market-based emission reduction programs. Some differences between our program and California's are the number of participating jurisdictions, the percentage of allowances that are distributed by auction, and the scope of affected compliance entities. RGGI focuses exclusively on the power sector, while California's program incorporates other economic sectors such as transportation and industry.

FORTNIGHTLY: Do you think other states will pair up and try to model their programs after your plan or that of California?

Speakes-Backman: Whether states look to the California model, the RGGI model, or to construct their own programs, it's a smart move to utilize existing market structures as the simplest, most cost effective method of reducing emissions.

Multi-state approaches like RGGI increase market liquidity and help to spread risk across more entities and a larger region. Regional approaches also more closely align with the structure of the electricity grid. Over the years, several states, regions and even nations have been interested in the RGGI formula for success. EPA's Clean Power plan has definitely increased states' interests in understanding how cost effective market-based regional programs like RGGI work.

FORTNIGHTLY: Your thoughts on the EPA's Clean Power Plan? Should it have gone further? How might you improve it?

Speakes-Backman: EPA's Clean Power Plan is an important step towards the development of an advanced energy infrastructure that delivers cleaner air, smarter energy and supports the economy. EPA conducted an unprecedented level of outreach to state economic and environmental regulators, as well as to organizations such as NARUC (National Association of Regulatory Utility Commissioners), to develop the proposal they issued in June.

In my opinion, EPA was responsive to stakeholders and developed a flexible plan recognizing the multitude of carbon pollution reduction strategies that are available and have been already demonstrated in the energy sector. The RGGI states are particularly pleased that EPA recognized the effectiveness of market-based regional programs such as RGGI that limit carbon emissions and empower states to pursue the most cost-effective reduction approaches possible.

Next, it will be important for EPA to refine its initial proposal, taking into account the comments it receives in December. For the RGGI states, we think the basic design of the Clean Power Plan is sound. We do have some questions and thoughts on their initial proposal that can essentially be boiled down to three elements:

Does the rule recognize states for early action taken to reduce carbon pollution from the power sector?

Are there more opportunities to achieve greater cost-effective carbon pollution reductions? As noted previously, the RGGI experience demonstrates that cost-effective reductions are feasible beyond the 30% reduction projected by EPA.

Does the rule provide for a transparent, verifiable, equitable and enforceable emissions reduction compliance targets?

FORTNIGHTLY: How would you address an audience from coal producing states or states where coal makes up most of the electricity base? How do you address their economic fears?

Speakes-Backman: In fact, Maryland's in-state generation is predominantly coal. In 2005, our percentage of in-state generation [from coal] was as high as 56 percent. As part of RGGI, and coupled with state energy initiatives, we have diversified our fuel mix and reduced our carbon footprint while actually growing our regional economy. We have seen our coal generation decrease to 44 percent of our generation mix, while our renewable and natural gas capacities have increased.

Also, we have used our RGGI auction proceeds to support energy efficiency and customer energy direct bill assistance. These reinvestments have helped more than 104,000 low-income Maryland families pay their energy bills and supported energy efficiency upgrades and weatherization for more than 4,300 low income families.

FORTNIGHTLY: Thoughts on the cross-state air pollution rule that affects 28 states and limits nitrogen oxide and sulfur dioxide and that CSAPR ruling will have practical implications on the Northeastern states?

Speakes-Backman: The CSAPR rule provides a solid regulatory framework for addressing ozone transport in the Eastern United States, and we are, of course, pleased with the Supreme Court's decision to uphold the rule. From a practical perspective, however, the decision will not have a significant impact on our air quality in the near term. The rule remains stayed in the D.C. Circuit Court of Appeals, and it's unclear whether EPA will propose more stringent NOx emission caps than those under the existing rule.

For us, we're really looking towards what we need to do for the 111(d) rule - I think that's the more pressing issue in front of us right now.

FORTNIGHTLY: Anything else to add?

Speakes-Backman: Only that I recognize that we, as utility regulators, are facing a unique challenge with the EPA proposed rules. But this presents us with a unique opportunity as well. RGGI states, along with many others, have already demonstrated that it is possible to achieve pollution reductions while supporting economic goals. While our mandated objectives of reliability, affordability, environmental soundness and economic growth can sometimes be competing, they are not necessarily mutually exclusive.

 

Michael R. Peevey, President, Calif. PUC

FORTNIGHTLY: Can you please discuss the cap-and-trade system that California has established and the success it is having?

a. Are emissions falling?

b. Are energy costs rising?

c. Are you selling credits or giving them away? How will this change in the future?

Michael R. Peevey, President, Calif. PUC: The cap-and-trade program established by the California Air Resources Board (ARB) has functioned very well so far, but it is early in the process to evaluate how successful the program has been in achieving emissions reductions. The state is only in the second year since the cap went into effect, and the ARB has not finished verifying greenhouse gas (GHG) emissions data reported for 2013.

Emissions from stationary sources fell steadily from 2008 to 2011, and then rose again in 2012, albeit to less than the 2008 level. The decreases in emissions are mostly attributable to the recession, and to some extent California's Renewables Portfolio Standard. Emissions rose in 2012 as the economy began to recover and more gas-fired generation was needed to replace the loss of the San Onofre Nuclear Generation Station. Despite that set back, we should meet our 2020 goal. The recession made that target easier, but as our economy recovers, the cap-and-trade program will play a larger role in keeping GHG emissions in check.

Due to both the recession and California's programs to promote efficiency and renewable energy, GHG allowance prices have hovered near the ARB's floor price of $11. Because the price-setting resource in California is primarily combined-cycled gas-fired generation, the GHG allowance price has had a modest effect on wholesale power prices, generally $5 or less per MWh.

The allowances associated with GHG emissions in the electricity sector are allocated by the ARB to the utilities, but the investor-owned utilities must auction all of the allowances they receive. In 2012, we were deliberating how the auction revenues should be used when the legislature narrowed the range of possibilities in the budget trailer bill, a provision of which stated that the revenues must be credited to the utilities' "residential, small business and emissions-intensive trade-exposed retail customers." These customer classes are effectively reimbursed for carbon costs that flow from the wholesale market to their retail rates. My preference is to compensate these customers in a way that preserves the conservation incentive of putting a price on GHG emissions.

In the decision implementing the trailer bill, the CPUC adopted my recommendation that emissions-intensive trade-exposed customers should receive annual rebates based on their output or historical energy consumption rather than through a rate reduction. Similarly, residential customers receive semi-annual climate credits on their bills (the first credit appeared on bills this past April). The credits are not tied to consumption - each household in a given utility service territory receives the same credit. That allows us to pass the GHG price through in residential rates to encourage efficiency and conservation, while compensating households from any increased costs that may occur as a consequence of putting a price on GHG pollution from fossil-fired generation. This year, each semi-annual credit ranged from $30 for PG&E customers to $194 for Pacific Power customers. We encourage customers to use their Climate Credit to make their homes more energy efficient and climate friendly, for example by participating in the Energy Upgrade California program (www.energyupgradeca.org).

Given the diverse nature of small business activity, the only practical way to compensate small business customers was through a rate reduction. However, the allocation of allowance revenues for the small business Climate Credit is scheduled to decrease over time so that the GHG price will increasingly appear in their bills over the course of several years. This will provide small businesses time to adjust to the GHG price.

FORTNIGHTLY: Can you describe the Renewables Portfolio Standard (RPS) there and whether the incumbent utilities are able to achieve their goals?

a. Are costs going up?

b. What fuels are making up that standard?

c. Is there room on the transmission grid?

d. Do you see this standard evolving and if so, how?

e. Do municipals have to comply with these standards?

Peevey: California's Renewables Portfolio Standard, which the legislature increased from 20 percent to 33 percent in 2011, is one of the most ambitious renewable energy standards in the country. The standard applies to all providers of retail electricity in California. The CPUC enforces the standard for the investor-owned utilities, Energy Service Providers, and Community Choice Aggregators and the Air Resources Board enforces it for publicly owned utilities.

California's program has been a resounding success. Collectively, the large investor-owned utilities (PG&E, Southern California Edison, and San Diego Gas & Electric) delivered 23 percent renewable energy in 2013, and they slightly exceeded the 20 percent requirement for the program's first compliance period, which covers 2011 to 2013. With 2,100 megawatts of new renewable capacity installed in 2013 to meet their RPS targets, California's investor-owned utilities added proportionally as much new capacity as Germany did. If you count the 600 megawatts of behind-the-meter solar installed last year, which generally doesn't count in California's RPS program, California's investor-owned utilities added considerably more capacity than Germany did. We anticipate that a total of 3,800 megawatts of RPS capacity will come online in 2014.

The utilities should easily meet the 33 percent target. Our projections show that if they renew expiring contracts with existing facilities, they already have sufficient existing and new capacity under contract to meet the target by 2020. This is true even if you assume that a significant number of contracts for new capacity ultimately fail to achieve operational status.

We will achieve the 33 percent goal at relatively modest cost to California's ratepayers. It is difficult to precisely estimate the incremental cost of the RPS program, but a consultant report in 2009 projected that attaining the 33 percent goal would increase average rates by roughly 7 percent, including the costs of any new transmission constructed to access renewable resources. With the substantial reduction in renewable energy prices over the past few years, the 7 percent estimate is likely an upper bound on actual costs by 2020.

Currently geothermal and wind account for most of the capacity in the RPS program, but the trend is clearly toward solar photovoltaic (PV) as its cost has plummeted. Solar PV projects dominated the bids in the utilities' 2012 and 2013 solicitations, and we expect that solar PV will account for 20 percent of the generation in the RPS program by 2020.

California has adequate transmission capacity in the pipeline to meet the 33 percent goal. Several important transmission projects have been recently completed or are under construction. The Sunrise Powerlink was completed in 2012, Devers-Palo Verde and El Dorado-Ivanpah were completed last year, and the East County project should be completed soon. The Tehachapi Renewable project has been delayed due to our decision last year to underground the portion of the line running through the community of Chino Hills. This will be the first undergrounded 500 kV project in the U.S., and it has presented some unique engineering challenges. Nonetheless, Edison should complete the line by 2017.

FORTNIGHTLY: What is the status of the CPUC's penalty case against PG&E for the San Bruno pipeline rupture?

Peevey: Two Administrative Law Judges (ALJs) of the CPUC have issued four decisions, called Presiding Officer Decisions (PODs), in connection with the CPUC's investigations of PG&E's operations and practices related to gas transmission, including the pipeline rupture in San Bruno. The PODs would penalize PG&E $1.4 billion, the largest safety-related penalty ever levied by a public utilities commission anywhere in the U.S. The ALJs' decisions will come before the CPUC's Commissioners to consider at a voting meeting. I have recused myself from any further participation in these proceedings, but the ALJs may modify their decisions by issuing modified decisions referred to as ModPODs. The other Commissioners also have the option of writing "Decisions Different" than the ALJ's PODs for their colleagues' consideration.

Since the tragic PG&E pipeline rupture in San Bruno, the CPUC has strengthened its commitment to safety. The CPUC has adopted a safety policy statement that defines the role of the Commissioners, commits the agency to constantly improving its safety efforts, and provides a unifying vision and guidance for the organization's multiple and disparate functions. In the aftermath of the San Bruno incident, the CPUC has taken a number of actions, both internally and with its regulated utilities, to ensure that safety is a priority. We convened an independent review panel to evaluate the safety practices of both the utilities and the CPUC. The panel issued 15 recommendations to the CPUC, and we have acted on all of them. Additionally, the National Transportation Safety Board (NTSB) issued five Safety Recommendations to the CPUC. Of those, the NTSB has determined that the CPUC has taken appropriate action on three and now considers them closed, while two are long-term items that are ongoing: overseeing PG&E pipeline testing of pipeline segments without records and investigating the San Bruno incident, for which a final decision is pending.

FORTNIGHTLY: What is the status of the San Onofre Nuclear Generating Station outage proceeding at the CPUC?

Peevey: In March 2014, the CPUC's Office of Ratepayer Advocates, The Utility Reform Network (TURN), Southern California Edison, and San Diego Gas & Electric (SDG&E) announced that they reached a proposed settlement for CPUC Commissioner consideration regarding the failed steam generator tubes at the San Onofre Nuclear Generating Station. Meanwhile, researchers from the University of California estimated that emissions increased by 9 million metric tons in 2012 as a result of the San Onofre closure.

This is not a trivial amount considering that California's total electricity-related GHG emissions, including emissions from imports, were approximately 100 million metric tons that year. As such, in response to the proposed settlement submitted by the settling parties, Commissioner Florio and the assigned Administrative Law Judges requested certain modifications, primarily to make the allocation of costs more favorable to ratepayers. Also, one of the modifications directed Edison and SDG&E shareholders to fund a five-year $25 million research effort through the University of California aimed at practical, near-term implementation of new technologies and processes to reduce emissions from electricity generation. The settling parties agreed to the changes and subsequently filed a revised proposed settlement for the CPUC's consideration in the near future. The Administrative Law Judges issued a Proposed Decision that would adopt the revised settlement, and it is scheduled for consideration at the CPUC's Nov. 20, 2014, Voting Meeting.

FORTNIGHTLY: Battery technology: Describe this standard and tell us if you feel it will contribute to the advancement of wind and solar energies? Will battery technologies improve as a result?

Peevey: Most of the analysis I have seen indicates that integrating large shares of renewable energy will require significant curtailment of intermittent generation without storage. One year ago, the CPUC issued a decision setting a 2020 procurement target of over 1,300 megawatts of storage capacity for the large electric utilities. The decision provides the utilities an off-ramp if they can demonstrate to the CPUC that the responses to their solicitations will not allow them to meet the target at a reasonable cost. Capacity will be procured via biennial solicitations beginning in 2014. A proposed decision on the CPUC's Oct. 16, 2014, agenda would approve the procurement framework for the first storage solicitation and would set a total target of over 110 megawatts of capacity.

[Editor's Note: The proposed decision on storage procurement on the agenda was issued as final on Oct. 22. See, Decision Approving Storage Procurement Framework and Program Applications, Decision No. 14-10-045, Oct. 16, 2014, Application Nos. 14-02-006, 14-02-007, 14-02-009.]

The storage procurement decision divided the 1,300 megawatts target among three different interconnection categories: transmission-level, distribution-level, and customer-sited. Of the total storage target, 200 megawatts is slated to come from customer-sited storage. The self-generation incentive program (SGIP) provides incentives for customer-sited storage, currently set at $1.60 per watt. Over one-quarter of the target for customer-sited installations is already connected or in the SGIP queue so I am confident we will meet the 200 megawatts goal.

In the same manner that the combined demand for solar PV in Europe and California enabled rapid decreases in the cost of solar PV, I hope that the combined demand for electric vehicles in California and elsewhere, along with the CPUC's energy storage procurement program will facilitate improvements in the performance and cost of storage technology.

 

Audrey Zibelman, Chair, NY PSC

FORTNIGHTLY: I've been reading about the state's regulatory initiative, known as Reforming the Energy Vision, or REV, and to be honest, it seems eerily familiar. That is, were not these same ideas discussed in the 1990s? We all known it is tough to engage consumers. Still true? If not, what's changed? What's driving this proposal?

Audrey Zibelman, Chair, NY PSC: Unlike the discussions that were held in the 1990s that focused simply on customer selection of retail suppliers, REV's focus includes looking at the wholesale as well as retail level. REV is far more encompassing than previous initiatives, driven in large part by the development of technology that did not exist 20 years ago.

While energy efficiency and demand response programs were given a level of lip service in the 1990s, the types of technology and communications systems, as well as customer demand for greater control over their use of energy, was nowhere at the level that exists today. The technology to make the distributed grid work is far more advanced than it was just a few years ago. This is true not only of the information technology that will form the backbone of the system, but also of distributed resources like solar and storage technologies, and building management systems.

Customer expectations have also changed dramatically. Customers demand more reliability than ever before from their utilities. At the same time customers expect that the businesses they interact with should have real time interoperable intelligence. In that respect, utilities are not in the same game with telecom, retail, automotive, entertainment, manufacturing, you name it. Getting customers involved is crucial to REV; but there are hundreds of companies willing to risk their capital to get involved with REV markets - just look at the party list in our proceeding - and this is a great indication that the market thinks customers are eager to engage.

Another thing that has changed is the set of challenges we are facing, and their imminence. Severe weather and aging infrastructure, against a backdrop of global competition, mean that business as usual just isn't good enough.

FORTNIGHTLY: In the last few years, New York State has endured two events of seismic proportion: Superstorm Sandy and the apparent gas-related incident in East Harlem. What has the commission done from its standpoint to beef up regulations in the aftermath of natural disasters?

Zibelman: The 2013-2014 State Budget included reforms implemented that strengthened the oversight and enforcement mechanisms of the PSC to ensure that major electric and gas utility companies are accountable and responsive to regulators and customers. These reforms were based on recommendations made by a blue ribbon panel formed in response to Superstorm Sandy. As a result, the PSC is now required, as called for by Governor Andrew M. Cuomo as a result of Sandy, to approve electric emergency response plans filed annually by electric corporations.

To ensure compliance with newly strengthened laws and regulations, the commission has the ability to initiate a civil penalty proceeding in situations where a utility has failed to file or properly implement a storm plan. In addition, a scorecard was created to assess utilities' performance for power restoration after a major outage. The scorecard will help establish standards to promote effective emergency preparation and response by utilities in the restoration of power to their communities. The scorecard will further provide quantitative measures to assist the commission in its evaluation of utility performance, its determination of whether to assess a penalty, and the magnitude of the penalty to be assessed.

In 2013, another blue ribbon panel formed by Governor Cuomo found that miles of aging pipeline are prone to leakage and vulnerable to storm damage, and it recommended accelerating pipeline replacement programs in flood-prone areas. That commission's recommendations were consistent with actions taken as part of the Energy Highway Blueprint to accelerate improvements to the natural gas distribution system, and the PSC's commitment to pipeline replacement programs.

Even before the blue ribbon panel's recommendations, incentive programs to reduce safety risks by replacing deteriorating and leak-prone infrastructure and/or reducing leak backlogs have been incorporated into rate agreements for utilities, and they are collectively working to update the gas distribution infrastructure annually. To accelerate replacement of leak-prone pipe in New York, the commission has approved several utility rate cases with accelerated investments. For instance, as part of the NFG rate case, on May 8, 2014, the PSC approved an increase in the replacement of additional miles of older, leak prone pipe annually or by nearly 20 percent.

As part of the Con Edison rate case, on February 21, 2014, the PSC approved an increase in the annual replacement rate of leak prone pipe of 40 percent by rate year three compared to current replacement levels. Con Edison will also continue its oil-to-gas conversion programs that will help expand natural gas service to more customers.

The Con Edison incident in East Harlem was on the distribution system, not on an interstate or intrastate ipeline. There has been no determination of cause yet; the National Transportation Safety Board (NTSB) continues its investigation. In addition to its own investigation, the PSC remains an active party in the NTSB investigation. To ensure all required safety requirements are being met, the PSC has been examining utility compliance with gas safety rules very closely, including, for instance, directing all gas utilities, including Con Edison, demonstrate that employees who perform plastic fusions on gas facilities are properly trained and certified.

FORTNIGHTLY: What has the commission done from its standpoint to deal with the aftermath of pipeline accidents? Any successes so far?

Zibelman: Ensuring and protecting the safety of the public is first and foremost, and that is why it is critically important that utilities comply completely with all safety regulations and follow all rules. The utilities have an aggressive maintenance program around leaks, pipe repair and replacement, among other safety precautions. As a result of rigorous PSC oversight, the state's gas utilities have steadily reduced the number of leaks in the system. In rare instance where a leak poses an actual safety hazard, the PSC requires the utility to take immediate and aggressive steps to eliminate the hazard.

Since 2004, PSC Staff have prepared a report that examines the performance of natural gas local distribution companies (LDCs) in New York State in three specific safety areas: damage prevention, emergency response, and leak management. These reports, based on data reported annually by LDCs, are used to track and monitor performance in areas critical to gas safety. In addition, staff completes annually, for each LDC in the State, an audit of their records in their offices and an audit of the compliance of their field operations with their documented procedures. LDCs are cited for violations in both cases. In each LDC's rate case, there is a metric established such that if that number of violations is exceeded in a given year, the LDC faces a negative revenue adjustment. The goal is to see a downward trend in the number of citations given to each LDC, with the eventual goal of full compliance. Staff focuses its work on higher risk categories, such as ensuring that pipe is operated at safe pressures.

FORTNIGHTLY: Let's move to natural gas fracking and the current moratorium. From the commission's perspective, does it have a dog in this fight? Would the lifting of the ban provide a new fuel source that could beef up energy security there?

Zibelman: The commission does not have a role to play in determining whether hydrofracturing should be allowed in the state. Regardless of the outcome of that discussion, the commission continues to develop initiatives to ensure that the state's energy distribution system remains affordable, resilient and clean. To that end, the commission has approved several collaborative proposals to expand the gas distribution system as a way to replace coal as a source for generating electricity, as well as making gas available to residential and business customers who currently use oil or propane.

For example, the commission recently approved a plan to allow an upstate utility, National Grid, to explore approaches to increase the availability of natural gas service. The commission is encouraging other utilities to propose similar gas expansion plans. Expanding natural gas service will provide significant economic and environmental benefits to New York consumers.

FORTNIGHTLY: Nuclear power and Indian Point. Could you give us an update? Is there a real chance this plant will be closed? Are you concerned about what might replace this energy?

Zibelman: Consolidated Edison and the New York Power Authority have developed a contingency plan to address the potential reliability impacts of closing Indian Point at the expiration of its licenses in 2016. Elements of the plan include: A package of three transmission system enhancements and a Con Edison energy efficiency/demand response program. The PSC approved the plan in November 2013 and concluded that it was an appropriate response to the potential reliability needs.

In addition, another element of the contingency plan involved securing generation resources via a NYPA RFP. An RFP was issued and there were several responses from bidders. However, the commission deferred decision on that element awaiting market response to anticipated capacity market changes. Since then, several generation owners announced they would reopen their mothballed generation facilities.

FORTNIGHTLY: NY is part of RGGI. Is that working? What has been the impact on rates? Emissions? Does the state also have an RPS standard? How has implementation gone?

Zibelman: New York State continues to participate in RGGI, and it has been successful in helping drive down emissions. In addition, New York has long had an RPS standard.

Recently, in an effort to further improve carbon reduction efforts, bolster renewable energy resource development, and strengthen energy efficiency activities, New York has become engaged in the process of creating a new Clean Energy Fund (CEF) to support the efforts of the New York State Energy Research and Development Authority (NYSERDA), and to replace NYSERDA's many separate efforts regarding the System Benefits Charge, Energy Efficiency Portfolio Standard, and Renewable Portfolio Standard. The fund would establish a cap on collections from ratepayers, starting in 2016 with an immediate $225 million reduction from the 2015 collections level, from $925 million to $700 million.

The CEF is designed to pursue three long-term outcomes. First, the CEF seeks to achieve greater levels of scale for clean energy in the State economy. Second, the CEF will be oriented to achieve scale, not only through the investment of public funds, but to foster new investment opportunities to attract private capital to invest in clean energy in New York. Initiatives oriented for scale and private capital attraction will then result in the third desired outcome: significant reduction in GHG emissions from New York's energy sector. To achieve these long-term outcomes the CEF's theme is "market transformation," and the CEF will employ approaches that will enable the entire clean energy supply chain - from technology developers to equipment wholesalers to financial institutions to building managers and construction contractors as well as to energy consumers seeking clean energy options - to create a new, integrated, self-sustaining clean energy market.

The NYSERDA CEF efforts will complement the separate, but significant utility-administered clean energy efforts, implemented through the REV-informed rate cases. REV, CEF and RGGI are three prongs in New York's GHG reduction strategy.

 

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